This invention relates generally to the field of perforating and treating subterranean formations to increase the production of oil and gas therefrom. More specifically, the invention provides a method for perforating and treating multiple intervals without the necessity of discontinuing treatment between steps or stages.
When a hydrocarbon-bearing, subterranean reservoir formation does not have enough permeability or flow capacity for the hydrocarbons to flow to the surface in economic quantities or at optimum rates, hydraulic fracturing or chemical (usually acid) stimulation is often used to increase the flow capacity. A wellbore penetrating a subterranean formation typically consists of a metal pipe (casing) cemented into the original drill hole. Typically, lateral holes (perforations) are shot through the casing and the cement sheath surrounding the casing to allow hydrocarbon flow into the wellbore and, if necessary, to allow treatment fluids to flow from the wellbore into the formation.
Hydraulic fracturing consists of injecting viscous fluids (usually shear thinning, non-Newtonian gels or emulsions) into a formation at such high pressures and rates that the reservoir rock fails and forms a plane, typically vertical, fracture (or fracture network) much like the fracture that extends through a wooden log as a wedge is driven into it. Granular proppant material, such as sand, ceramic beads, or other materials, is generally injected with the later portion of the fracturing fluid to hold the fracture(s) open after the pressures are released. Increased flow capacity from the reservoir results from the more permeable flow path left between grains of the proppant material within the fracture(s). In chemical stimulation treatments, flow capacity is improved by dissolving materials in the formation or otherwise changing formation properties.
Application of hydraulic fracturing as described above is a routine part of petroleum industry operations as applied to individual target zones of up to about 60 meters (200 feet) of gross, vertical thickness of subterranean formation. When there are multiple or layered reservoirs to be hydraulically fractured, or a very thick hydrocarbon-bearing formation (over about 60 meters), then alternate treatment techniques are required to obtain treatment of the entire target zone. The methods for improving treatment coverage are commonly known as xe2x80x9cdiversionxe2x80x9d methods in petroleum industry terminology.
When multiple hydrocarbon-bearing zones are stimulated by hydraulic fracturing or chemical stimulation treatments, economic and technical gains are realized by injecting multiple treatment stages that can be diverted (or separated) by various means, including mechanical devices such as bridge plugs, packers, down-hole valves, sliding sleeves, and baffle/plug combinations; ball sealers; particulates such as sand, ceramic material, proppant, salt, waxes, resins, or other compounds; or by alternative fluid systems such as viscosified fluids, gelled fluids, or foams, or other chemically formulated fluids; or using limited entry methods. These and all other methods for temporarily blocking the flow of fluids into or out of a given set of perforations will be referred to herein as xe2x80x9cdiversion agents.xe2x80x9d
In mechanical bridge plug diversion, for example, the deepest interval is first perforated and fracture stimulated, then the interval is isolated mechanically and the process is repeated in the next interval up. Assuming ten target perforation intervals, treating 300 meters (1,000 feet) of formation in this manner would typically require ten jobs over a time interval of ten days to two weeks with not only multiple fracture treatments, but also multiple and separate perforating and bridge plug running operations. At the end of the treatment process, a wellbore clean-out operation would be required to remove the bridge plugs and put the well on production. The major advantage of using bridge plugs or other mechanical diversion agents is high confidence that the entire target zone is treated. The major disadvantages are the high cost of treatment resulting from multiple separate trips into and out of the wellbore and the risk of complications resulting from so many separate operations on the well. For example, a bridge plug can become stuck in the casing and need to be drilled out at great expense. A further disadvantage is that the required wellbore clean-out operation may damage some of the successfully fractured intervals.
One alternative to using bridge plugs is filling the just fractured interval of the wellbore with fracturing sand, commonly referred to as the Pine Island technique. The sand column essentially plugs off the already fractured interval and allows the next interval to be perforated and fractured independently. The primary advantage is elimination of the problems and risks associated with bridge plugs. The disadvantages are that the sand plug does not give a perfect hydraulic seal and it can be difficult to remove from the wellbore at the end of all the fracture stimulation treatments. Unless the well""s fluid production is strong enough to carry the sand from the wellbore, the well may still need to be cleaned out with a work-over rig or coiled tubing unit. As before, additional wellbore operations increase costs, mechanical risks, and risks of damage to the fractured intervals.
Another method of diversion involves the use of particulate materials, granular solids that are placed in the treating fluid to aid diversion. As the fluid is pumped, and the particulates enter the perforations, a temporary block forms in the zone accepting the fluid if a sufficiently high concentration of particulates is deployed in the flow stream. The flow restriction then diverts fluid to the other zones. After the treatment, the particulate is removed by produced formation fluids or by injected wash fluid, either by fluid transport or by dissolution. Commonly available particulate diverter materials include benzoic acid, napthalene, rock salt (sodium chloride), resin materials, waxes, and polymers. Alternatively, sand, proppant, and ceramic materials, could be used as particulate diverters. Other specialty particulates can be designed to precipitate and form during the treatment.
Another method for diverting involves using viscosified fluids, viscous gels, or foams as diverting agents. This method involves pumping the diverting fluid across and/or into the perforated interval. These fluid systems are formulated to temporarily obstruct flow to the perforations due to viscosity or formation relative permeability increases; and are also designed so that at the desired time, the fluid system breaks down, degrades, or dissolves (with or without adding chemicals or other additives to trigger such breakdown or dissolution) such that flow can be restored to or from the perforations. These fluid systems can be used for diversion of matrix chemical stimulation treatments and fracture treatments. Particulate diverters and/or ball sealers are sometimes incorporated into these fluid systems in efforts to enhance diversion.
Another possible diversion technique is the xe2x80x9climited-entryxe2x80x9d diversion method in which the entire target zone of the formation to be treated is perforated with a very small number of perforations, generally of small diameter, so that the pressure loss across those perforations during pumping promotes a high, internal wellbore pressure. The internal wellbore pressure is designed to be high enough to cause all of the perforated intervals to fracture simultaneously. If the pressure were too low, only the weakest portions of the formation would fracture. The primary advantage of limited entry diversion is that there are no inside-the-casing obstructions like bridge plugs or sand that need to be removed from the well or which could lead to operational problems later. The disadvantage is that limited entry fracturing often does not work well for thick intervals because the resulting fracture is frequently too narrow (the proppant cannot all be pumped away into the narrow fracture and remains in the wellbore), and the initial, high wellbore pressure may not last. As the sand material is pumped, the perforation diameters are often quickly eroded to larger sizes that reduce the internal wellbore pressure. The net result can be that not all of the target zone is stimulated. An additional concern is the potential for flow capacity into the wellbore to be limited by the small number of perforations.
The problems resulting from failure to stimulate the entire target zone or using mechanical methods that pose greater risk and cost as described above can be addressed by using limited, concentrated perforated intervals diverted by ball sealers. The zone to be treated could be divided into sub-zones with perforations at approximately the center of each of those sub-zones, or sub-zones could be selected based on analysis of the formation to target desired fracture locations. The fracture stages would then be pumped with diversion by ball sealers at the end of each stage. Specifically, 300 meters (1,000 feet) of gross formation might be divided into ten sub-zones of about 30 meters (about 100 feet) each. At the center of each 30 meter (100 foot) sub-zone, ten perforations might be shot at a density of three shots per meter (one shot per foot) of casing. A fracture stage would then be pumped with sand-laden fluid followed by ten or more ball sealers, at least one for each open perforation in a single perforation set or interval. The process would be repeated until all of the perforation sets were fractured. Such a system is described in more detail in U.S. Pat. No. 5,890,536 issued Apr. 6, 1999.
Historically, all zones to be treated in a particular job have been perforated prior to pumping treatment fluids, and ball sealers have been employed to divert treatment fluids from zones already broken down or otherwise taking the greatest flow of fluid to other zones taking less, or no, fluid prior to the release of ball sealers. Treatment and sealing theoretically proceeded zone by zone depending on relative breakdown pressures or permeabilities, but problems were frequently encountered with balls prematurely seating on one or more of the open perforations outside the targeted interval and with two or more zones being treated simultaneously.
FIG. 1 illustrates the general concept of using ball sealers as a diversion agent for stimulation of multiple perforation intervals. FIG. 1 shows perforation intervals 32, 33, and 34 of an example well 30. Perforations 36 penetrate wellbore casing 38 and cement sheath 39. In FIG. 1, perforated interval 33 has been stimulated with hydraulic proppant fracture 46 and is in the process of being sealed by ball sealers 12 (in wellbore) and ball sealers 14 (already seated on perforations). Under ideal circumstances, as the ball sealers 12 and ball sealers 14 seal perforation interval 33, the wellbore pressure would rise causing another single perforation interval to break down. This technique presumes that each perforation interval or sub-zone would break down and fracture at sufficiently different pressure so that each stage of treatment would enter only one set of perforations. However, in some instances, multiple perforation intervals may break down at nearly the same pressure so that a single stage of treatment may actually enter multiple intervals and lead to sub-optimal stimulation. Although a method exists to design a multiple-stage ball sealer-diverted fracture treatment so that only one set of perforations is fractured by each stage of fluid pumped, such as that disclosed in U.S. Pat. No. 6,186,230 issued Feb. 13, 2001, the optimum use of this method is dependent on formation characteristics and stimulation job requirements; as such, in some instances it may not be possible to optimally implement the treatment so that only one zone is treated at a time.
The primary advantages of ball sealer diversion are low cost and low risk of mechanical problems. Costs are low because the process can typically be completed in one continuous operation, usually during just a few hours of a single day. Only the ball sealers are left in the wellbore to either flow out with produced hydrocarbons or drop to the bottom of the well in an area known as the rat (or junk) hole. The primary disadvantage is the inability to be certain that only one set of perforations will fracture at a time so that the correct number of ball sealers are dropped at the end of each treatment stage. In fact, optimal benefit of the process depends on one fracture stage entering the formation through only one perforation set and all other open perforations remaining substantially unaffected during that stage of treatment. Further disadvantages are lack of certainty that all of the perforated intervals will be treated and of the order in which these intervals are treated while the job is in progress. In some instances, it may not be possible to control the treatment such that individual zones are treated with single treatment stages.
Other methods have been proposed to address the concerns related to fracture stimulation of zones in conjunction with perforating. These proposals include 1) having a sand slurry in the wellbore while perforating with overbalanced pressure, 2) dumping sand from a bailer simultaneously with firing the perforating charges, and 3) including sand in a separate explosively released container. These proposals all allow for only minimal fracture penetration surrounding the wellbore and are not adaptable to the needs of multi-stage hydraulic fracturing as described herein.
Accordingly, there is a need for a method for individually treating each of multiple intervals within a wellbore while maintaining the economic benefits of multistage treatment. There is also a need for a fracture treatment design method that can economically reduce the risks inherent in the currently available fracture treatment options for hydrocarbon-bearing formations with multiple or layered reservoirs or with thickness exceeding about 60 meters (200 feet).
This invention provides a method for treatment of multiple perforated intervals so that only one such interval is treated during each treatment stage while at the same time determining the sequence order in which intervals are treated. The inventive method will allow more efficient chemical and/or fracture stimulation of many reservoirs, leading to higher well productivity and higher hydrocarbon recovery (or higher infectivity) than would otherwise have been achieved.
One embodiment of the invention involves perforating at least one interval of the one or more subterranean formations penetrated by a given wellbore, pumping the desired treatment fluid without removing the perforating device from the wellbore, deploying some item or substance in the wellbore to removably block further fluid flow into the treated perforations, and then repeating the process for at least one more interval of subterranean formation.
Another embodiment of the invention involves perforating at least one interval of the one or more subterranean formations penetrated by a given wellbore, pumping the desired treatment fluid without removing the perforating device from the wellbore, actuating a mechanical diversion device in the wellbore to removably block further fluid flow into the treated perforations, and then repeating the process for at least one more interval of subterranean formation.